The present invention is sponsored by The Petroleum Institute of Abu Dhabi.
1. Technical Field
The embodiments herein generally relate to a method of characterization or determination of wettability of reservoir rock. The embodiments herein more particularly relate to a new technique for determining the wettability of reservoir rock samples using Washburn Equation for calculating the contact angles.
2. Description of the Related Art
Reservoir wettability is one of the most important parameters, which directly control the fluid flow by having an effect on the location and distribution of the fluids. It also has an influence on core analyses such as capillary pressure, relative permeability, irreducible water and residual oil saturation and indirectly influences electrical properties of reservoir rocks. The wettability of reservoir rock influences many aspects of reservoir performance, particularly water-flooding and enhanced oil recovery techniques. This makes the understanding and accurate determination of the wettability of any oil reservoir very crucial for optimizing oil recovery.
Wettability is the relative preference of a solid surface to be coated by a certain fluid in a system. In a rock/oil/brine system, it is a measure of the preference that the rock surface has for an oil or water. When the rock is water-wet, there is a tendency for water to contact the majority of the rock surface. Similarly, in an oil-wet system, the rock is preferentially in contact with the oil; the location of the two fluids is reversed from the water-wet case, oil will contact the majority of the rock surface. When the rock surface does not display a preference for oil or water contact, intermediate wettability exists. Cases where water coats the surface of small pores while oil coats the surface of large pores are fractional wet or mixed wet, if continuous paths of oil and water wet rock are present.
Reservoir wettability is one of the most important parameters that control many aspects of the performance and quantification of hydrocarbon reservoirs. The validity of laboratory core analyses depends largely on the degree to which the test core represents the reservoir. If the wettability of the test core is not the same as that of the reservoir, then the measured parameters of capillary pressure, relative permeability, irreducible water saturation, residual oil saturation, and prediction of water flooding performance are inaccurate. Interpretation of water saturation from resistivity logs by Archie's method requires an accurate value of saturation exponent, in, which wettability influences. The possibility of applying an enhanced oil recovery method is related to the oil saturation remaining in the reservoir and its areal and vertical distribution, as well as its microscopic continuity in the pores network of the reservoir. The original wetting properties of the reservoir and its distribution play an important role in the choice of improved recovery processes to be applied. Accordingly, a knowledge of reservoir wettability is a significant asset in the decision making process concerning many different aspects of oil production.
Wettability of a reservoir rock can range from strongly water-wet to strongly oil-wet, and in between (intermediate wet) if the rock has no strong preference for either oil or water. The wetting conditions are strongly affected by the following factors: rock mineralogy, constituents and conditions of the pore surfaces, reservoir oil and formation water, adsorption or deposition of oil constituents on the rock surface, oil composition and reservoir conditions. Reservoir rocks are complex structures and often comprise a variety of mineral types of different wettability characteristics. Clean sandstone or quartz is extremely water-wet; sandstone reservoir rock is commonly moderately water-wet. Carbonates tendency is towards intermediate to oil-wet. Equilibrium between the constituents and conditions of the pore surfaces, the reservoir oil and formation water influences decide the reservoir wetting preferences. Variations in wettability are related to the thickness of the water film separating oil and reservoir rock during the oil displacement process. If stable thick water films separate the oil from the rock, the system will be water-wet. Thin water films (increasing height above free water level) can rupture allowing oil to contact the rock surface. Adsorption or deposition of oil constituents on the rock surface such as the polar oil components also affects the wetting conditions. Asphaltenes are candidates for wettability alteration to an oil wet state due to their polar groups that may interact and bind to the mineral surface. The polar compounds in resins and asphaltenes combine hydrophilic and hydrophobic characteristics, which are wettability-altering components in the oil phase. In relation to oil composition, Black-oil composition determines the solubility of the polar components. A crude oil that is a poor solvent for its own surfactants has a greater propensity to change wettability than one that is a good solvent. The Reservoir Conditions such as reservoir temperature, pressure and saturation history affect reservoir wettability.
The realization that rock wettability can be altered by adsorbable crude oil components led to the idea that heterogeneous or fractional wettability exist in reservoir rock. In fractional wettability, crude oil components are adsorbed in certain areas of the rock, so a portion of the rock is oil-wet, while the rest is strongly water-wet. Note that this is conceptually different from intermediate wettability, which assumes that all portions of the rock surface have a slight but equal preference to wetting by water or oil. Mixed wettability is a special type of fractional wettability. Unlike the fractional wettability, the oil-wet surfaces in mixed wettability assume specific locations and form continuous paths through the larger pores while the smaller pores remain water-wet and contain no oil.
Regardless of the rock mineralogy, hydrocarbon reservoir rocks are likely water wet before oil migration. They may change their wetting preference thereafter. The reservoir's saturation history influences the reservoir wetting preference and the degree of these wetting preferences. In a thick (100's of feet) oil-bearing formation, wettability can vary with depth, with a greater water-wetting preference near the bottom of the transition zone and a greater oil-wetting preference near the top. The higher zones have a greater capillary pressure, which can counteract the disjoining pressure and destabilize the water film, allowing surface-active components in the oil to contact the solid. In the lower structures, the solid surfaces mostly retain the water film.
Both quantitative and qualitative methods are in use for determining the wettability of a system. Qualitative methods investigate different criteria to determine the degree of water or oil wetness including imbibition rates, relative permeability curves, permeability/saturation relationships, capillary pressure curves and reservoir logs. Quantitative methods, on the other hand, try to quantify wettability by either determining the wettability angles or through some wettability indices. Some of the common quantitative wettability tests available in the industry include: Amott Wettability Method, USBM Wettability Method, Combined Amott-Harvey and USBM Wettability Method and Contact Angle Method.
Amott Wettability Method is commonly used technique to measure wettability of core samples. Amott wettability is the ratio of saturation change by spontaneous imbibition to the saturation change by both spontaneous imbibition and forced displacement. Amott method combines both capillary and viscous force effects to measure the average wettability of the core samples. A core sample is prepared by centrifuging under oil until irreducible water saturation (Swirr), placed into a water-filled tube where water spontaneously imbibes over a period of time (10-20 days) until attaining equilibrium. The sample is placed in a flow cell for forced displacement of oil by water until reaching residual oil saturation (Sor). The process is then reversed for spontaneous and forced oil imbibition, driving the water out of the core sample until reaching irreducible water saturation (Swirr). Separate ratios of spontaneous imbibition to total saturation change for water, Iw, and oil, Io, are termed the water and oil imbibition indices, respectively. Preferentially water-wet cores have a positive displacement-by-water ratio and a zero value for the displacement-by-oil ratio. The displacement by-water ratio approaches +1 as the water wetness increases. Similarly, oil-wet cores have a positive displacement-by-oil ratio and a zero displacement-by-water ratio. Both ratios are zero for neutrally wet cores. The Amott-Harvey index, IAH, combined the two ratios (Iw and Io) into a single wettability index. It is defined as the difference between the water spontaneous imbibition ratio, Iw, and that of the oil, Io, (IAH=Iw−Io). The result is a number between +1 (strongly water-wetting) and −1 (strongly oil-wetting). If the oil ratio (Io) has positive value and the water ratio (Iw) is zero, then the core is preferentially oil wet. Contrary to this, when the water ratio (Iw) has positive value and the oil ratio (Io) is zero, it means that the core sample is preferentially water wet. If both values are zero, then the core is neutrally wet. The main problem with the Amott wettability test and its modifications is its insensitivity near neutral wettability. The test measures the ease with which the wetting fluid can spontaneously displace the non-wetting one. However, neither fluid will spontaneously imbibe and displace the other when the contact angle varies from roughly 60 to 120°. In addition, the limiting contact angle above which spontaneous imbibition will not occur depends on the initial saturation of the core.
USBM Wettability Method is an alternative quantitative method for determining the wettability index by using the hysteresis loop of capillary pressure curves. The USBM test also measures the average wettability of the core. USBM wettability test is faster than Amott test and it is more sensitive near neutral wettability. On the other hand, the USBM test cannot determine whether a system has fractional or mixed wettability, while the Amott test is sometimes sensitive to this wettability state. In some fractional- or mixed-wet systems, both water and oil will imbibe freely. The Amott method will have positive displacement by-water and displacement-by-oil ratios, indicating that the system is non-uniformly wetted. During the USBM test, a centrifuge spins the core sample at stepwise-increasing speeds. The sample starts at irreducible water saturation (Swirr) in a water filled tube. After spinning for some period of time at several spin rates, the sample reaches residual oil saturation (Sor) and it is placed into an oil-filled tube for another series of measurements. The areas under each of the capillary-pressure curves and the zero capillary-pressure line are calculated, and the logarithm of the ratio of the water-increasing to oil-increasing areas gives the USBM wettability index. The measurement range extends from +∞ (strongly water wetting) to −∞ (strongly oil wetting), although most measurement results are in a range of +1 to −1.
The basis of the Amott-Harvey index is relative changes in saturation, while the USBM index is a measure of the energy needed to make the forced displacement, making them related but independent indicators of wettability. Sharma and Wunderlich proposed a method by combining the Amott-Harvey and USBM methods and by modifying the USBM method, using a centrifuge rather than flooding with water and oil to obtain the forced flooding states. There are two advantages of the combined USBM/Amott method over the standard USBM method. They improved USBM resolution by accounting for the saturation changes that occur at zero capillary pressure and a data to enable a calculation of the Amott, Amott-Harvey and the USBM indices.
FIG. 1 shows a prior art illustrating a graph showing the steps of the Combined Amott-Harvey and USBM Wettability Methods. With respect to FIG. 1, the graph shows five steps of the method. They are: initial oil drive (I), spontaneous (free) imbibition of brine (2), brine drive (3), spontaneous (free) imbibition of oil (4) and oil drive (5). The areas under the brine- and oil-drive curves A1 and A2 provide the USB Mindex, while the Amott index uses the volumes of free and total water and oil displacements.
The contact angle testing methods measure the wettability of a mineral surface in contact with a fluid from the reservoir. Different methods of contact angle measurement exist in the oil industry. The Sessile Drop and the Modified Sessile Drop are two popular contact angle methods. In both the methods, a mineral crystal is mounted in a test cell comprising entirely of inert materials to prevent contamination. The Sessile Drop method uses a single flat and polished mineral crystal. The modified sessile drop method uses two flat and polished mineral crystals mounted parallel to each other on adjustable posts. Because a sandstone is primarily composed of quartz and limestone of calcite, a crystal of quartz or calcite simulates the pore surfaces of the reservoir rock. After cleaning, the surface is aged with formation brine. A drop of crude oil is placed in contact with the aged surface. The contact angle (θ), of the fluid on the mineral surface determines the intrinsic wettability of a reservoir rock. With a range of 0° to 180°, low angles are water wet while high angles are oil wet. In the 1980s, the Thin Layer Wicking method was developed for measuring the contact angles of all minerals, even with irregular shapes, such as no swelling clays, talc, dolomite, limestone, calcite, silicates and the cuboids hematite. In this method, a thin layer of powdered solid sample is deposited on glass slide. This facilitates penetration of the liquid into the layer and a sharp visible progressing contact angle line is visible. However, the Thin Layer Wicking method is limited to powdered rock samples and is not applicable for representing the wettability characteristics of reservoir rocks that have heterogeneous mineralogical composition.
Treiber et. al. used the water advancing contact angle to estimate the wettability of 55 oil reservoirs. In Treiber's et. al. study deoxygenated synthetic formation brine and dead anaerobic crudes were tested on quartz and calcite crystals at reservoir temperature. Contact angles (measured through the water) from 0° to 75° were deemed water-wet, 75° to 105° intermediate wettability, and 105° to 180° oil-wet. Although the range of wettabilities was divided into three regions, it should be strongly emphasized that these are arbitrary divisions. The wettability of different reservoirs can vary within the broad spectrum from strongly water-wet to strongly oil-wet.
Morrow described two initial conditions as reference and non-reference for calculating the cut-off values by using an advancing and receding contact angle and spontaneous imbibition data. For Instance, by using an Imbibition Curvature Ratio vs Intrinsic contact angle plot, the limiting value between water wet and intermediate zones is described as 62°. Similarly, the cut-off values for advancing contact angle is described as 0° to 62° for water wet region, 62° to 133° for Intermediately wet zone, and 133° to 180° for Oil wet zone.
Chilingar and Yen conducted an extensive research work on 161 limestone, dolomitic limestone, calcitic dolomite, and dolomite cores and classified the cut-off values for strongly oil wet (160° to 180°), oil wet (100° to 160°), intermediate wet (80° to 100°), water wet (80° to 20°), and strongly water wet (80° to 20°).
Using the Amott-Harvey index, IAH, Cuiec stated that the system is water-wet when +0.3≦IAH≦−1, intermediate wet when −0.3<IAH<0.3, and oil-wet when −1≦IAH≦−0.3. The measurement range of the USBM test method extends from +∞ (strongly water wetting) to −∞ (strongly oil wetting). The system would be diagnosed as water wet when the USBM index is near +1, intermediately wet when it is near 0 and oil wet when it is near −1. The USBM index was further subdivided and classified as follows, neutral or mixed wet (−0.1 to +0.1), slightly water wet (+0.1 to +0.3), water wet (+0.3 to +1.0), slightly oil wet (−0.1 to −0.3) and oil wet (−0.3 to −1.0).
Many of the wettability measurements are imprecise, particularly near neutral wettability. One method may show that a core is mildly oil-wet, while another shows that the core is mildly water-wet. The main problem with the Amott wettability test and its modifications is that they are insensitive near neutral wettability. The test measures the ease with which the wetting fluid can spontaneously displace the non-wetting one. However, neither fluid will spontaneously imbibe and displace the other, when the contact angle varies from roughly 60 to 120°. In addition, the limiting contact angle above which spontaneous imbibition will not occur depends on the initial saturation of the core. Moreover, the Amott method is rather very slow requiring many experimental steps.
USBM testing method is faster than the Amott test and is more sensitive near neutral wettability. However, the USBM test cannot determine whether a system has fractional or mixed wettability, while the Amott test is sometimes sensitive to that. Both the USBM test and the Amott test have serious weakness with respect to discriminating between systems that fall within the wettability range of 0° to 55°. Drainage curves in the contact angle range of 0° to 55° are not significantly affected by wettability but there is systematic decrease in imbibition capillary pressure with increase in contact angle. If trapping of the non-wetting phase is complete Iw be unity, because forced displacement is not expected to reduce the trapped residual non-wetting phase, except at high capillary numbers. Thus, the Amott index does not discriminate between systems, which attain residual non-wetting phase without change in sign of imbibition capillary pressure. A comparable problem arises with the USBM test.
Although contact angle methods measure wettability directly, but there are some limitations. The contact angle cannot take into account the heterogeneity of the rock surface. Contact angles are measured on a single mineral crystal, while a core contains many different constituents. Furthermore, the wettability of clays in the reservoir cannot be examined with this method, as the contact angles are measured on flat smooth and shiny rock surface. Experimentally, it is generally found that a liquid drop on a surface can have many different stable contact angles. There is hysteresis in the contact-angle measurements. The reported contact angles are either the water-advancing or water receding contact angles. The advancing angle, θadv, is measured by pulling the periphery of a drop over a surface, while the receding contact angle. θrec; is measured by pushing it back. The difference θadv−θrec, is the contact-angle hysteresis and can be greater than 60°. Another important limitation of the contact angle method is that the required length of equilibration time cannot be reproduced in the lab. This may lead to problems such as erroneous classification of wetting state and sometimes to reproducibility issues. One other obvious limitations of wettability characterization using contact angle measurement is the absence of a standard reference. Consequently, except at the end point wetting states, the classification of wetting state from contact angle measurement is arbitrary and subjective.
Although it covers all wettability ranges sufficiently, the contact angle wettability testing methods are seldom utilized due to the many limitations. In addition to the limitations, the Amott and USBM testing methods are very demanding in terms of experimental setup and procedure. Moreover, the handling of the core samples to achieve the different parts of the tests may risk an alteration of the wettability during a testing. Additionally, Amott-Harvey and USBM reports wettability in terms of an index rather the contact angles.
These limitations call for a need of a new method for characterization of wettability that requires much simpler experimental setup, requires less experimental effort to perform, determines wettability in all possible ranges and finally determines wettability in terms of a contact angle rather than on a wettability index.
The above mentioned shortcomings, disadvantages and problems are addressed herein and which will be understood by reading and studying the following specification.